Attached files
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2010
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OR
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£
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Commission File Number 1-2745
Southern Natural Gas Company
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
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63-0196650
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.)
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El Paso Building
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1001 Louisiana Street
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Houston, Texas
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77002
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(Address of Principal Executive Offices)
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(Zip Code)
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Telephone Number: (713) 420-2600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer £
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Accelerated filer £
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Non-accelerated filer R
(Do not check if a smaller reporting company)
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Smaller Reporting Company £
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R
State the aggregate market value of the voting equity held by non-affiliates of the registrant: None
Documents Incorporated by Reference: None
SOUTHERN NATURAL GAS COMPANY
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Below is a list of terms that are common to our industry and used throughout this document:
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/d
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per day
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LNG
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liquefied natural gas
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BBtu
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billion British thermal units
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MMcf
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million cubic feet
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Bcf
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billion cubic feet
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Tonne
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metric ton
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Bcfe
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billion cubic feet of natural gas equivalents
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When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to “us”, “we”, “our”, “ours”, or “SNG”, we are describing Southern Natural Gas Company and/or our subsidiaries.
Overview and Strategy
We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 60 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso Corporation (El Paso), and 40 percent by El Paso SNG Holding Company, L.L.C., a wholly owned subsidiary of El Paso. In 2010, EPB acquired an additional 35 percent interest (20 percent in June and 15 percent in November) in us from El Paso.
Our pipeline system and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
Our strategy is to enhance the value of our transportation and storage business by:
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providing outstanding customer service;
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successfully executing on time and on budget for our committed expansion projects;
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developing new growth projects in our market and supply areas;
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maintaining the integrity and ensuring the safety of our pipeline system and other assets;
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optimizing our contract portfolio; and
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focusing on increasing utilization, efficiency and cost control in our operations.
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Pipeline System. Our pipeline system consists of approximately 7,600 miles of pipeline with a design capacity of 3,700 MMcf/d. During 2010, 2009 and 2008, average throughput was 2,505 BBtu/d, 2,322 BBtu/d and 2,339 BBtu/d. This system extends from supply basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. We are the principal natural gas transporter to the southeastern markets in Alabama, Georgia and South Carolina. Our system is also connected to the Elba Island LNG terminal near Savannah, Georgia. This terminal is owned by EPB and has a peak send-out capacity of approximately 1.8 Bcf/d and a storage capacity of 11.5 Bcfe.
FERC Approved Projects. As of December 31, 2010, we had the following FERC approved expansion projects on our system. For a further discussion of these expansion projects, see Part II, Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations.
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Project
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Capacity
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Description
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Anticipated Completion or
In-Service Date
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South System III
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370
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To add 81 miles of pipeline and 17,310 of horsepower compression; each phase will add an additional 122 MMcf/d of capacity
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2011-2012(1)
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Southeast Supply Header Phase II(2)
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350
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To add approximately 26,000 of horsepower compression to the jointly owned pipeline facilities
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June 2011
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(1) This project will be completed in three phases. We placed Phase I of the project in service in January 2011 and anticipate to place Phase II and III in service in June 2011 and June 2012.
(2) This project is operated by Spectra Energy Corp.
Storage Facilities. We own and operate 100 percent of the Muldon storage facility in Monroe County, Mississippi. We also own a 50 percent interest in and operate Bear Creek Storage Company, LLC (Bear Creek) in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by us and our affiliate, Tennessee Gas Pipeline Company (TGP). Our interest in Bear Creek and the Muldon storage facilities have a combined working natural gas storage capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. We provide storage services to our customers utilizing the Bear Creek and the Muldon storage facilities at our FERC tariff rate. The working storage capacity at the Bear Creek facility is committed equally to TGP and us.
Markets and Competition
Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.
The southeastern market served by our pipeline is the fastest growing natural gas demand region in the United States. Demand for deliveries from our pipeline is characterized by two peak delivery periods, the winter heating season and the summer cooling season.
The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shales, is rapidly increasing. This shift will affect the supply patterns, the flows and the rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources. Our pipeline is directly connected to the Haynesville Shale formation in northern Louisiana. Our pipeline is also indirectly connected, through new interconnecting pipelines, to the Barnett Shale, Bossier Sands, Woodford Shale and Fayetteville Shale. It is possible that gas from these sources will increasingly displace receipts over time and could impact the flows on the system and our shipper contracts.
Imports of LNG have fluctuated in the past in response to changing gas prices within North America, Europe and Asia. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.
Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.
We face competition in a number of our key markets and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. Our four largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines and we compete with several pipelines for the transportation business of our other customers. We also compete with pipelines and gathering systems for connection to new supply sources. Our most direct competitor is Transcontinental Gas Pipe Line Company, L.L.C., which owns an approximately 10,500 mile pipeline extending from Texas to New York. It has firm transportation contracts with some of our largest customers, including Atlanta Gas Light Company, Alabama Gas Corporation, Southern Company Services, and SCANA Corporation.
For a further discussion of factors impacting our markets and competition, see Item 1A, Risk Factors.
Customers and Contracts
Our existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
The following table details our customer and contract information related to our pipeline system as of December 31, 2010. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.
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Customer Information
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Contract Information
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Approximately 260 firm and interruptible customers.
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Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately seven years.
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Major Customers:
Atlanta Gas Light Company(1)
(979 BBtu/d)
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Expire in 2013-2015.
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(84 BBtu/d)
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Expires in 2024.
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Southern Company Services
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(43 BBtu/d)
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Expire in 2011-2013.
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(390 BBtu/d)
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Expire in 2017-2018.
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(375 BBtu/d)
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Expires in 2032.
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Alabama Gas Corporation
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(352 BBtu/d)
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Expires in 2013.
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SCANA Corporation
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(315 BBtu/d)
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Expire in 2013-2019.
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(1) Atlanta Gas Light Company releases on a monthly basis a significant portion of its firm capacity to a subsidiary of SCANA Corporation.
Regulatory Environment
Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority also extends to:
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rates and charges for natural gas transportation and storage;
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certification and construction of new facilities;
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extension or abandonment of services and facilities;
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maintenance of accounts and records;
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relationships between pipelines and certain affiliates;
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terms and conditions of service;
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depreciation and amortization policies;
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acquisition and disposition of facilities; and
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initiation and discontinuation of services.
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Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations. For a further discussion of the potential impact of regulatory matters on us, see Item 1A, Risk Factors.
Environmental
A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.
Employees
We do not have employees. Following our reorganization in 2007, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf.
CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.
Risks Related to Our Business
The success of our business depends on many factors beyond our control.
The results of our business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes we transport and store depend on the actions of third parties that are based on factors beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipeline to the risk that we will not be able to renew contracts at expiration or that we will be required to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their system in order to grow our business. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.
The volume of gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline system, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our system. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our system. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.
Furthermore, our ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.
The agencies that regulate our business and our customers could affect our profitability.
Our business is extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.
Our existing rates may be challenged by complaint. The FERC commenced several complaint proceedings in 2009 and 2010 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us. For a discussion of our rate case, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.
Certain of our transportation services are subject to negotiated rate contracts that may not allow us to recover our costs of providing the services.
Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.
Our revenues are generated under contracts that must be renegotiated periodically.
Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline system could decrease over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. Our ability to extend and replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause us to negotiate short-term contracts or turn back their capacity when our contracts expire.
The expansion of our pipeline system by constructing new facilities subjects us to construction and other risks that may adversely affect us.
We frequently expand the capacity of our existing pipeline and storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;
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the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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potential changes in federal, state and local statutes, regulations, and orders;
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impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;
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our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;
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our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;
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the failure of suppliers and contractors to meet their performance and warranty obligations; and
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the lack of transportation, storage or throughput commitments.
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Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return.
We depend on certain key customers for a significant portion of our revenues and the loss of any of these key customers could result in a decline in our revenues.
We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2010, our contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas Corporation and SCANA Corporation represented approximately 25 percent, 19 percent, 8 percent and 8 percent, respectively of our firm transportation capacity. The loss of any material portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us.
The costs to maintain, repair and replace our pipeline system may exceed our expected levels.
Much of our pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including due to third party excavation near our pipeline system, unexpected degradation of our pipeline system, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipeline. In addition, as indicated above there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. We are also subject to inherent risks associated with operating gas storage facilities including potential gas losses and field degradation.
We do not own all the land on which our pipeline system and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Our loss of or interference with these rights could have a material adverse effect on us.
There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.
Accounting policies for FERC regulated pipelines are in certain instances different from U.S. general accepted accounting principles (GAAP) for nonregulated entities. For example, FERC accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for nonregulated entities. In determining whether to account for regulatory assets on our pipeline, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.
The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. For example, we are not significantly impacted in the short-term by reductions in the supply or demand for natural gas since we recover most of our revenues from reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our business can be negatively impacted by sustained downturn in supply and demand for natural gas. One of the major factors that will impact natural gas demand will be the potential growth of natural gas in the power generation market, particularly driven by the speed and level of coal-fired power generation that is replaced with natural gas-fired power generation. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:
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adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;
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adverse changes in geopolitical factors and unexpected wars, terrorist activities and others acts of aggression;
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technological advancements that may drive further increases in production from natural gas shales;
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competition from imported LNG and alternate fuels;
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increased prices of natural gas that could negatively impact demand;
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increased costs to transport natural gas;
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adoption of various energy efficiency and conservation measures; and
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perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.
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The price for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:
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changes in regional and domestic supply and demand;
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changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain our transportation revenues and renew transportation contracts in supply basins that are not as competitive as other alternatives;
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changes in the costs of transporting natural gas;
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increased federal and state taxes, if any, on the transportation of natural gas;
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the price and availability of supplies of alternative energy sources;
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the amount of capacity available to transport natural gas.
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Our business is subject to competition from third parties which could negatively affect us.
The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies and storage companies in the transportation and storage of natural gas, as well as with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. There have also been various proposals over time to construct new pipelines into our market area.
Our operations are subject to operational hazards and uninsured risks which could negatively affect us.
Our operations are subject to a number of inherent risks including fires, earthquakes, adverse weather conditions (such as extreme cold or heat, hurricanes, tornadoes, lightning and flooding) and other natural disasters; terrorist activity or acts of aggression; the collision of equipment of third parties on our infrastructure (such as damage caused to our underground pipeline by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards. Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. Our offshore operations may encounter additional marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, and governmental regulations. In addition, although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near the Gulf of Mexico and other coastal regions.
While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm/hurricane exposures, and in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.
We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.
Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls, and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state or local lands are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands both onshore and offshore, which are regulated by the Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation and Enforcement.
The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operation or otherwise negatively impact us.
The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulation may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to implement or amend federal, state, and local laws and regulations that could negatively impact our business, which includes among others:
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Climate Change and other Emissions. There have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate GHG emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline system. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipelines, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
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●
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Renewable/Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.
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●
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Pipeline Safety. Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipeline and subjecting additional pipelines (including gathering facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.
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We are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline system. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.
We are exposed to the credit and performance risk of our key contractors and suppliers.
As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction, and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.
We have certain contingent liabilities that could exceed our estimates.
We have certain contingent liabilities associated with litigation, regulatory and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continued to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 7). Although we believe that we have established appropriate reserves for our litigation and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.
We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.
We are subject to financing and interest rate risks.
Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.
Risks Related to Our Affiliation with El Paso and EPB
El Paso and EPB file reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.
We are a consolidated subsidiary of EPB and El Paso.
As a consolidated subsidiary of EPB and El Paso, subject to limitations in our indentures, EPB and El Paso have substantial control over:
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•
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decisions on our financing and capital raising activities;
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•
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mergers or other business combinations;
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•
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our acquisitions or dispositions of assets; and
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•
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our participation in EPB’s cash management program.
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EPB and El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.
Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.
Our business requires the retention and recruitment of a skilled workforce. If El Paso is unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.
Our relationship with El Paso and EPB and their financial condition subjects us to potential risks that are beyond our control.
Due to our relationship with El Paso and EPB, adverse developments or announcements concerning them or their other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. El Paso, EPB and their subsidiaries, including us, are on a stable outlook with Moody’s Investor Service, Fitch Ratings and Standard & Poor’s rating agencies. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our, EPB’s and El Paso’s leverage, liquidity, and credit profile. Any reduction in our, El Paso’s or EPB’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital. Below are the ratings assigned to our, El Paso’s and EPB’s senior unsecured indebtedness at December 31, 2010.
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Rating Agency
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Moody’s Investor
Service
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Standard &
Poor’s
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Fitch
Ratings
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Credit Rating
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SNG
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Baa3 (1)
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BB (2)
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BBB- (1)
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EPB
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Ba1 (2)
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BB (2)
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BBB- (1)
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El Paso
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Ba3 (2)
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BB-(2)
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BB+ (2)
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____________
(1) Investment grade.
(2) Below investment grade.
EPB provides cash management services and El Paso provides other corporate services for us. We are currently required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. In addition, we conduct commercial transactions with some of our affiliates. If EPB, El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.
Our relationship with El Paso and EPB subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.
Although EPB has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and EPB, including material regulatory filings, any significant sale of our assets, mergers and certain changes in affiliated service agreements. Conflicts of interest or disagreements could arise between El Paso and EPB with regard to such matters requiring unanimous approval, which could negatively impact our future operations.
We have not included a response to this item since no response is required under Item 1B of Form 10K.
A description of our properties is included in Item 1, Business, and is incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interest in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.
A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.
All of our partnership interests are held by El Paso and EPB and, accordingly, are not publicly traded.
We are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis from legally available funds that have been approved for payment by our Management Committee. We made cash distributions to our partners of $257 million in 2010, $171 million in 2009 and $200 million in 2008. Additionally, in January 2011, we made a cash distribution of approximately $47 million to our partners.
The following selected historical financial data is derived from our audited consolidated financial statements and is not necessarily indicative of results to be expected in the future. The selected financial data should be read together with Item 7, Management’s Discussion and Analysis and Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.
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As of or for the Year Ended December 31,
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2010
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2009
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2008
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2007
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2006
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(In millions)
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Operating Results Data:
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Operating revenues
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$ | 548 | $ | 510 | $ | 540 | $ | 482 | $ | 462 | ||||||||||
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Operating income
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308 | 255 | 271 | 242 | 218 | |||||||||||||||
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Net income
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267 | 208 | 235 | 202 | 162 | |||||||||||||||
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Financial Position Data:
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Total assets
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$ | 2,687 | $ | 2,659 | $ | 2,629 | $ | 2,803 | $ | 3,395 | ||||||||||
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Long-term debt, less current maturities
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910 | 910 | 910 | 1,098 | 1,096 | |||||||||||||||
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Partners’ capital/stockholder’s equity
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1,624 | 1,614 | 1,577 | 1,542 | 1,644 | |||||||||||||||
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Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors. We have included a discussion in this MD&A of our business, expansion projects, results of operations, liquidity and capital resources, contractual obligations and critical accounting estimates that may affect us as we operate in the future.
Overview
Business. Our primary business consists of the interstate transportation and storage of natural gas. We face varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.
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Type
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Description
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Percent of 2010
Revenues
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Reservation
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Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.
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88
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Usage and Other
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Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.
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12
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The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather.
We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately seven years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.
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Contracted
Capacity
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Percent of
Contracted Capacity
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Reservation Revenue
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Percent of
Reservation Revenue
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| (BBtu/d) | (In millions) | |||||||||||||||
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2011
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140 | 3 | $ | 8 | 2 | |||||||||||
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2012
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2 | — | — | — | ||||||||||||
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2013
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2,065 | 49 | 249 | 50 | ||||||||||||
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2014
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36 | 1 | 6 | 1 | ||||||||||||
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2015
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360 | 9 | 46 | 9 | ||||||||||||
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2016 and beyond
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1,617 | 38 | 192 | 38 | ||||||||||||
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Total
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4,220 | 100 | $ | 501 | 100 | |||||||||||
Expansion Projects. During 2011, we plan to spend approximately $125 million in capital on our backlog of expansion projects. Our most significant FERC approved projects are described below.
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•
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South System III. This expansion project will be completed in three phases, at an estimated total cost of approximately $300 million, with each phase expected to add an additional 122 MMcf/d of capacity. Phase I of the project was placed in service in January 2011 on time and under budget. The estimated in-service dates are June 2011 for Phase II and June 2012 for Phase III. Construction agreements have been finalized for Phase II.
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Southeast Supply Header Phase II. We own an undivided interest in the northern portion (Phase I) of the Southeast Supply Header project jointly owned by Spectra Energy Corp and CenterPoint Energy, which added a 115-mile supply line to the western portion of our system. This project provides us access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins. Phase I of the project was placed in service in September 2008. The estimated cost to us for Phase II of this project is approximately $60 million and is expected to provide us with an additional 350 MMcf/d of supply capacity. We expect to place Phase II of the project in service in June 2011.
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In addition to our backlog of contracted organic growth projects, we have other projects that are in various phases of commercial development. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads and would have in-service dates for 2015 and beyond. If we are eventually successful in contracting for these new loads, the capital requirements could be substantial and would be incremental to our backlog of contracted organic growth projects. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our backlog of contracted organic growth projects.
Results of Operations
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of both consolidated operations and an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense and (ii) affiliated interest income, net. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results in 2010 compared with 2009 and 2009 compared with 2008.
Operating Results:
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2010
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2009
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2008
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(In millions, except for volumes)
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Operating revenues
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$ | 548 | $ | 510 | $ | 540 | ||||||
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Operating expenses
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(240 | ) | (255 | ) | (269 | ) | ||||||
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Operating income
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308 | 255 | 271 | |||||||||
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Earnings from unconsolidated affiliates
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14 | 11 | 13 | |||||||||
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Other income, net
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7 | 2 | 10 | |||||||||
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EBIT
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329 | 268 | 294 | |||||||||
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Interest and debt expense
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(63 | ) | (62 | ) | (72 | ) | ||||||
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Affiliated interest income, net
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1 | 2 | 13 | |||||||||
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Net income
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$ | 267 | $ | 208 | $ | 235 | ||||||
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Throughput volumes (BBtu/d) (1)
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2,505 | 2,322 | 2,339 | |||||||||
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(1) Throughput volumes include billable transportation throughput volumes for storage injection.
EBIT Analysis:
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2010 to 2009
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2009 to 2008
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Operating
Revenue
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Operating
Expense
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Other
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Total
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Operating
Revenue
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Operating
Expense
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Other
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Total
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Favorable/(Unfavorable)
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(In millions)
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Reservation and other services revenues
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$ | 47 | $ | — | $ | — | $ | 47 | $ | 24 | $ | (3 | ) | $ | — | $ | 21 | |||||||||||||||
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AFUDC on expansions
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— | — | 9 | 9 | — | — | (12 | ) | (12 | ) | ||||||||||||||||||||||
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Gas not used in operations and other natural gas activities
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(8 | ) | 7 | — | (1 | ) | (15 | ) | 22 | — | 7 | |||||||||||||||||||||
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Calpine bankruptcy
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— | — | — | — | (35 | ) | — | — | (35 | ) | ||||||||||||||||||||||
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Operating and general and administrative expenses
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— | 10 | — | 10 | — | — | — | — | ||||||||||||||||||||||||
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Other(1)
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(1 | ) | (2 | ) | (1 | ) | (4 | ) | (4 | ) | (5 | ) | 2 | (7 | ) | |||||||||||||||||
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Total impact on EBIT
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$ | 38 | $ | 15 | $ | 8 | $ | 61 | $ | (30 | ) | $ | 14 | $ | (10 | ) | $ | (26 | ) | |||||||||||||
____________
(1) Consists of individually insignificant items.
Reservation and Other Services Revenues. In January 2010, the FERC approved our rate case settlement which among other factors, increased our base tariff rates effective September 1, 2009 which resulted in higher reservation and other services revenues for the years ended December 31, 2010 and 2009.
AFUDC on Expansions. We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on equity funds related to our construction of long-lived assets that is recorded as other income on our income statements. For the year ended December 31, 2010 when compared to 2009, we benefitted from an increase in other income of approximately $9 million associated with the equity portion of AFUDC primarily on our South System III and Southeast Supply Header Phase II projects. Other income for the year ended December 31, 2009 was reduced by approximately $12 million associated with the equity portion of AFUDC due to lower capital expenditures as compared to 2008 primarily due to the completion of the Cypress Phase II and Southeast Supply Header Phase I projects which were placed in service in May 2008 and September 2008.
Gas Not Used in Operations and Other Natural Gas Activities. Prior to September 1, 2009, the financial impacts of gas not used in operations were based on the price of natural gas and the amount of natural gas we were allowed to retain according to our tariff, relative to the amounts of natural gas we used for operating purposes and the cost of operating our electric compression facilities. Volumes from any excess natural gas retained and not used in operations were shared with our customers. Effective September 1, 2009, we implemented a volume tracker as part of our rate case settlement and therefore we no longer share retained gas not used in operations with our customers. For the year ended December 31, 2010 when compared with 2009, our EBIT was favorably impacted by $5 million due to the implementation of the gas volumetric tracker, partially offset by $7 million due to the elimination of our fuel sharing mechanism. Additionally, we experienced favorable impacts to our EBIT in 2010 compared to 2009 due to higher costs of $4 million associated with replacement of depleted storage volumes in 2009.
We periodically perform an assessment of our natural gas volumes in our storage fields, the results of which may have negative impacts to our results of operations if we determine a storage loss has occurred. During 2010, our EBIT was unfavorably impacted by $2 million due to a gas loss at one of our storage facilities.
For the year ended December 31, 2009, our EBIT was favorably impacted $22 million due to favorable revaluation of retained volumes on our system compared with 2008, offset by lower revenues of approximately $15 million due to favorable sales of excess gas not used in operations in 2008.
Calpine Bankruptcy. During 2008, we recognized revenue related to distributions received under Calpine’s approved plan of reorganization.
Operating and General and Administrative Expenses. Our operating and general and administrative expenses were lower for the year ended December 31, 2010 compared with 2009 primarily due to lower benefits, payroll and contractor costs net of reimbursements from our affiliates related to their shared pipeline services.
Interest and Debt Expense
Interest and debt expense for the year ended December 31, 2009, was $10 million lower than in 2008 primarily due to lower average outstanding debt balances resulting from the retirement and repurchases of debt in June and September 2009. For further information on our outstanding debt balances, see Item 8, Financial Statements and Supplementary Data, Note 6.
Affiliated Interest Income, net
Affiliated interest income, net for the year ended December 31, 2009 was $11 million lower compared to 2008 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. During 2009, the average advances due from El Paso decreased primarily due to debt retirement and repurchases in June and September 2008 funded with recoveries of our note receivable.
In conjunction with EPB’s acquisition of an additional interest in us in November 2010, we terminated our participation in El Paso’s cash management program and began to participate in EPB’s cash management program. The following table shows the average advances due from El Paso and payable to EPB, and the average short-term interest rates for the year ended December 31:
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2010
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2009
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2008
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(In millions, except for rates)
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Average advance due from El Paso
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$ | 88 | $ | 85 | $ | 300 | ||||||
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Average advance due to EPB
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1 | — | — | |||||||||
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Average short-term interest rate on affiliate note receivable
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1.5 | % | 1.7 | % | 4.4 | % | ||||||
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Average short-term interest rate on affiliate note payable
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0.8 | % | — | — | ||||||||
Liquidity and Capital Resources
Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, amounts available to us under EPB’s cash management program and capital contributions from our partners. At December 31, 2010, we had a note payable to EPB of approximately $12 million which was classified as current on our balance sheet. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of EPB’s and El Paso’s cash management programs. Our primary uses of cash are for working capital, capital expenditures and for required distributions to our partners.
Although financial conditions have improved, continued volatility in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.
We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flow from operating activities, amounts available to us under EPB’s cash management program and capital contributions from our partners. As of December 31, 2010, EPB had approximately $450 million of capacity available to it under its $750 million revolving credit facility and $69 million of cash. While we do not anticipate a need to directly access the financial markets in 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.
2010 Cash Flow Activities. Our cash flows for the year ended December 31, 2010 are summarized as follows (in millions):
|
Cash Flow from Operations
|
||||
|
Net income
|
$ | 267 | ||
|
Non-cash income adjustments
|
64 | |||
|
Change in assets and liabilities
|
(24 | ) | ||
|
Total cash flow from operations
|
307 | |||
|
Other Cash Inflows
|
||||
|
Investing activities
|
||||
|
Proceeds from the sale of assets
|
8 | |||
|
Net change in note receivable from affiliate
|
154 | |||
|
Return of capital from investment in unconsolidated affiliate
|
15 | |||
| 177 | ||||
|
Financing activities
|
||||
|
Net change in note payable to affiliate
|
12 | |||
|
Total cash inflows
|
189 | |||
|
Cash Outflows
|
||||
|
Investing activities
|
||||
|
Capital expenditures
|
217 | |||
|
Acquisition
|
18 | |||
| 235 | ||||
|
Financing activities
|
||||
|
Distributions to partners
|
257 | |||
|
Total cash outflows
|
492 | |||
|
Net change in cash and cash equivalents
|
$ | 4 | ||
During 2010, we generated $307 million of operating cash flow. We utilized these amounts to maintain our system as well as pay distributions to our partners. During the year ended December 31, 2010, we paid cash distributions of approximately $257 million to our partners. In addition, in January 2011 we paid a cash distribution to our partners of approximately $47 million. Our cash capital expenditures for the year ended December 31, 2010 and those planned for 2011 are listed below:
|
2010
|
Expected
2011
|
|||||||
|
(In millions)
|
||||||||
|
Maintenance
|
$ | 67 | $ | 64 | ||||
|
Expansion
|
150 | 128 | ||||||
|
Total
|
$ | 217 | $ | 192 | ||||
Our expected 2011 expansion capital expenditures primarily relate to our South System III and Southeast Supply Header Phase II expansion projects. Our maintenance capital expenditures primarily relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through amounts available to us under EPB’s cash management program and capital contributions from our partners.
For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.
Contractual Obligations
We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt, while other obligations, such as operating leases, storage and electric commitments, and capital commitments are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2010, for each of the periods presented (all amounts are undiscounted):
|
Due in
less than 1 Year
|
Due in
1 to 3 Years
|
Due in
3 to 5 Years
|
Thereafter
|
Total
|
||||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
Long-term debt:
|
||||||||||||||||||||
|
Principal
|
$ | — | $ | — | $ | — | $ | 911 | $ | 911 | ||||||||||
|
Interest
|
61 | 123 | 123 | 559 | 866 | |||||||||||||||
|
Operating leases
|
3 | 6 | 6 | 5 | 20 | |||||||||||||||
|
Other contractual commitments and purchase obligations:
|
||||||||||||||||||||
|
Capital commitments
|
27 | — | — | — | 27 | |||||||||||||||
|
Other commitments
|
11 | 3 | — | — | 14 | |||||||||||||||
|
Total contractual obligations
|
$ | 102 | $ | 132 | $ | 129 | $ | 1,475 | $ | 1,838 | ||||||||||
Long-Term Debt (Principal and Interest). Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related fixed rate debt based on the contractual interest rate. For a further discussion of our debt obligations, see Item 8, Financial Statements and Supplementary Data, Note 6.
Operating Leases. For a further discussion of these obligations see Item 8, Financial Statements and Supplementary Data, Note 7.
Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:
|
•
|
Capital Commitments. Included in these amounts are commitments for purchasing pipe and related assets in our pipeline operations, and various other maintenance, engineering, procurement and construction contracts.
|
|
•
|
Other Commitments. Included in these amounts are commitments primarily for storage services. We have excluded asset retirement obligations and reserves for litigation and environmental remediation as these liabilities are not contractually fixed as to timing and amount.
|
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 7, which is incorporated herein by reference.
Off-Balance Sheet Arrangements
We have no off-balance sheet financing entities or structures with third parties other than our equity investment in Bear Creek, our accounts receivable sales program, and our letter of credit associated with the construction costs related to our Southeast Supply Header project. For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7, 10 and 11, which is incorporated herein by reference.
Critical Accounting Estimates
Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates.
Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board’s accounting standards on rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.
Accounting for Environmental and Legal Reserves. We accrue environmental and legal reserves when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, and in the case of environmental reserves, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, estimates of associated onsite, offsite and groundwater technical studies and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each matter. As of December 31, 2010, we had accrued approximately $2 million for legal matters.
Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2010, our postretirement benefit plan was under funded by $3 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rates used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.
Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded as either a regulatory asset or liability. A one-percentage point change in the primary assumptions would not have had a significant effect on net postretirement benefit cost. The following table shows the impact of a one percent change to the funded status for the year ended December 31, 2010 (in millions):
|
Change in
Funded Status
|
||||
|
One percentage point increase in:
|
||||
|
Discount rates
|
$ | 5 | ||
|
Health care cost trends
|
(5 | ) | ||
|
One percentage point decrease in:
|
||||
|
Discount rates
|
$ | (5 | ) | |
|
Health care cost trends
|
4 | |||
We are exposed to the risk of changing interest rates. At December 31, 2010, we had a note payable to EPB of approximately $12 million, with a variable interest rate of 0.8% that is payable upon demand. While we are exposed to changes in interest expense based on changes to the variable interest rate, the fair value of this note payable approximates the carrying value due to the note being payable upon demand and the market-based nature of the interest rate.
The table below shows the carrying value, related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities based on quoted market prices for the same or similar issues.
|
December 31, 2010
|
December 31, 2009
|
|||||||||||||||||||||||
|
|
Expected Fiscal Year of Maturity of
Carrying Amounts
|
|
|
|||||||||||||||||||||
|
|
2011-2015 |
Thereafter
|
Total
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||||||||
|
(In millions, except for rates)
|
||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Long-term debt — fixed rate
|
$ | — | $ | 910 | $ | 910 | $ | 984 | $ | 910 | $ | 977 | ||||||||||||
|
Average effective interest rate
|
6.8 | % | ||||||||||||||||||||||
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:
|
•
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2010.
Report of Independent Registered Public Accounting Firm
The Partners of Southern Natural Gas Company
We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Natural Gas Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2011
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
|
2010
|
2009
|
2008
|
|||||||||
|
Operating revenues
|
$ | 548 | $ | 510 | $ | 540 | ||||||
|
Operating expenses
|
||||||||||||
|
Operation and maintenance
|
154 | 173 | 189 | |||||||||
|
Depreciation and amortization
|
59 | 55 | 53 | |||||||||
|
Taxes, other than income taxes
|
27 | 27 | 27 | |||||||||
| 240 | 255 | 269 | ||||||||||
|
Operating income
|
308 | 255 | 271 | |||||||||
|
Earnings from unconsolidated affiliates
|
14 | 11 | 13 | |||||||||
|
Other income, net
|
7 | 2 | 10 | |||||||||
|
Interest and debt expense
|
(63 | ) | (62 | ) | (72 | ) | ||||||
|
Affiliated interest income, net
|
1 | 2 | 13 | |||||||||
|
Net income
|
$ | 267 | $ | 208 | $ | 235 | ||||||
See accompanying notes.
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions)
|
December 31,
|
||||||||
|
|
2010
|
2009
|
||||||
|
ASSETS
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | 4 | $ | — | ||||
|
Accounts and note receivable
|
||||||||
|
Customer
|
3 | 7 | ||||||
|
Affiliates
|
— | 64 | ||||||
|
Other
|
26 | 2 | ||||||
|
Materials and supplies
|
16 | 15 | ||||||
|
Other
|
14 | 9 | ||||||
|
Total current assets
|
63 | 97 | ||||||
|
Property, plant and equipment, at cost
|
3,885 | 3,709 | ||||||
|
Less accumulated depreciation and amortization
|
1,390 | 1,411 | ||||||
|
Total property, plant and equipment, net
|
2,495 | 2,298 | ||||||
|
Other assets
|
||||||||
|
Investment in unconsolidated affiliate
|
56 | 79 | ||||||
|
Note receivable from affiliate
|
— | 112 | ||||||
|
Other
|
73 | 73 | ||||||
| 129 | 264 | |||||||
|
Total assets
|
$ | 2,687 | $ | 2,659 | ||||
|
LIABILITIES AND PARTNERS’ CAPITAL
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts and note payable
|
||||||||
|
Trade
|
$ | 25 | $ | 19 | ||||
|
Affiliates
|
28 | 27 | ||||||
|
Other
|
31 | 16 | ||||||
|
Taxes payable
|
13 | 9 | ||||||
|
Accrued interest
|
18 | 18 | ||||||
|
Asset retirement obligations
|
1 | 14 | ||||||
|
Other
|
6 | 5 | ||||||
|
Total current liabilities
|
122 | 108 | ||||||
|
Long-term debt
|
910 | 910 | ||||||
|
Other liabilities
|
31 | 27 | ||||||
|
Commitments and contingencies (Note 7)
|
||||||||
|
Partners’ capital
|
1,624 | 1,614 | ||||||
|
Total liabilities and partners’ capital
|
$ | 2,687 | $ | 2,659 | ||||
See accompanying notes.
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
2010
|
2009
|
2008
|
||||||||||
|
Cash flows from operating activities
|
||||||||||||
|
Net income
|
$ | 267 | $ | 208 | $ | 235 | ||||||
|
Adjustments to reconcile net income to net cash from operating activities
|
||||||||||||
|
Depreciation and amortization
|
59 | 55 | 53 | |||||||||
|
Earnings from unconsolidated affiliate, adjusted for cash distributions
|
8 | 2 | 3 | |||||||||
|
Other non-cash income items
|
(3 | ) | (1 | ) | (5 | ) | ||||||
|
Asset and liability changes
|
||||||||||||
|
Accounts receivable
|
28 | 4 | 13 | |||||||||
|
Change in deferred purchase price from accounts receivable sales
|
(26 | ) | — | — | ||||||||
|
Accounts payable
|
(9 | ) | 9 | 7 | ||||||||
|
Other current assets
|
(7 | ) | 18 | (5 | ) | |||||||
|
Other current liabilities
|
2 | 10 | (9 | ) | ||||||||
|
Non-current assets
|
(13 | ) | — | (11 | ) | |||||||
|
Non-current liabilities
|
1 | (19 | ) | 4 | ||||||||
|
Net cash provided by operating activities
|
307 | 286 | 285 | |||||||||
|
Cash flows from investing activities
|
||||||||||||
|
Capital expenditures
|
(217 | ) | (138 | ) | (138 | ) | ||||||
|
Net change in note receivable from affiliate
|
154 | (18 | ) | 289 | ||||||||
|
Acquisition
|
(18 | ) | — | — | ||||||||
|
Proceeds from the sale of assets
|
8 | 41 | — | |||||||||
|
Return of capital from investment in unconsolidated affiliate
|
15 | — | — | |||||||||
|
Net cash provided by (used in) investing activities
|
(58 | ) | (115 | ) | 151 | |||||||
|
Cash flows from financing activities
|
||||||||||||
|
Payments to retire long-term debt
|
— | — | (236 | ) | ||||||||
|
Distributions to partners
|
(257 | ) | (171 | ) | (200 | ) | ||||||
|
Net change in note payable to affiliate
|
12 | — | — | |||||||||
|
Net cash used in financing activities
|
(245 | ) | (171 | ) | (436 | ) | ||||||
|
Net change in cash and cash equivalents
|
4 | — | — | |||||||||
|
Cash and cash equivalents
|
||||||||||||
|
Beginning of period
|
— | — | — | |||||||||
|
End of period
|
$ | 4 | $ | — | $ | — | ||||||
|
Supplemental cash flow information related to continuing operations
Interest paid, net of amounts capitalized
|
$ | 59 | $ | 61 | $ | 75 | ||||||
See accompanying notes.
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In millions)
|
|
||||
|
January 1, 2008
|
$ | 1,542 | ||
|
Net income
|
235 | |||
|
Distributions
|
(200 | ) | ||
|
December 31, 2008
|
1,577 | |||
|
Net income
|
208 | |||
|
Distributions
|
(171 | ) | ||
|
December 31, 2009
|
1,614 | |||
|
Net income
|
267 | |||
|
Distributions
|
(257 | ) | ||
|
December 31, 2010
|
$ | 1,624 | ||
See accompanying notes.
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
We are a Delaware general partnership, originally formed in 1935 as a corporation. We are owned 60 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso Corporation (El Paso), and 40 percent by El Paso SNG Holding Company, L.L.C., a wholly owned subsidiary of El Paso. Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.
We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our interstate natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects in periods prior to 2007 when we changed our legal structure to a general partnership, and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Materials and Supplies
We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators at specified index prices. Imbalances are settled either as cash outs or in-kind, subject to the terms of our tariff.
Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.
We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for an increase or decrease in our transportation and storage rates. Currently, our depreciation rates vary from less than one percent to 20 percent per year.
When we retire property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements.
Included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheet if deemed probable of recovery through future rates charged to our customers.
We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.
Asset and Investment Divestitures/Impairments
We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows.
Revenue Recognition
Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.
Postretirement Benefits
We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 8.
In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.
Income Taxes
We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because information regarding each partner’s tax attributes in us is not available to us.
2. Acquisition/Divestiture
In 2010, we purchased certain pipeline assets from Elba Express Company, L.L.C. (Elba Express), our affiliate, for $18 million and sold certain pipeline assets to Elba Express for net proceeds of $8 million. We recorded both the purchase and sale at their historical cost and accordingly, we recognized no gain or loss on these transactions.
3. Fair Value of Financial Instruments
At December 31, 2010 and 2009, the carrying amounts of cash and cash equivalents and trade receivables and payables represented their fair value because of the short-term nature of these instruments. At December 31, 2010, we had a note payable to EPB of approximately $12 million with a variable interest rate of 0.8%. At December 31, 2009, we had an interest bearing note receivable from El Paso of approximately $154 million due upon demand, with a variable interest rate of 1.5%. While we are exposed to changes in interest expense based on changes to the variable interest rate, the fair value of our note payable approximates the carrying value due to the note being payable on demand and the market-based nature of the interest rate.
In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:
|
2010
|
2009
|
|||||||||||||||
|
|
Carrying
Amount
|
Fair Value
|
Carrying
Amount
|
Fair Value
|
||||||||||||
|
(In millions)
|
||||||||||||||||
|
Long-term debt
|
$ | 910 | $ | 984 | $ | 910 | $ | 977 | ||||||||
4. Regulatory Assets and Liabilities
Our regulatory assets are included in other current and non-current assets on our balance sheets. Our regulatory liabilities are included in other non-current liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Current regulatory assets
|
||||||||
|
Difference between gas retained and gas consumed in operations
|
$ | 13 | $ | — | ||||
|
Other
|
1 | 4 | ||||||
|
Total current regulatory assets
|
14 | 4 | ||||||
|
Non-current regulatory assets
|
||||||||
|
Taxes on capitalized funds used during construction
|
28 | 29 | ||||||
|
Unamortized loss on reacquired debt
|
29 | 32 | ||||||
|
Other
|
6 | 1 | ||||||
|
Total non-current regulatory assets
|
63 | 62 | ||||||
|
Total regulatory assets
|
$ | 77 | $ | 66 | ||||
|
Non-current regulatory liabilities
|
||||||||
|
Postretirement benefits
|
$ | 9 | $ | 5 | ||||
|
Other
|
6 | 3 | ||||||
|
Total non-current regulatory liabilities
|
$ | 15 | $ | 8 | ||||
The significant regulatory assets and liabilities include:
Difference Between Gas Retained and Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers in subsequent fuel filing periods.
Taxes on Capitalized Funds Used During Construction. Regulatory asset balance established in periods prior to 2007 when we changed our legal structure to a general partnership, to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and recovered over the depreciable lives of the long lived asset to which they relate.
Unamortized Loss on Reacquired Debt. Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered over the original life of the debt issue through the cost of service.
Postretirement Benefits. Represents unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.
5. Property, Plant and Equipment
Capitalized Costs During Construction. Interest costs capitalized were $2 million, $1 million and $3 million during the years ended December 31, 2010, 2009 and 2008. Equity amounts capitalized were $7 million, $3 million and $7 million during the years ended December 31, 2010, 2009 and 2008.
Construction Work-In Progress. At December 31, 2010 and 2009, we had approximately $212 million and $34 million of construction work in progress included in our property, plant and equipment.
Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transportation facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from five to 12 percent based on when the liabilities were recorded. We record changes in estimates based on changes in the expected amount and timing of payments to settle our obligations. We intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.
The net asset retirement obligation as of December 31 reported on our balance sheets in current and other non-current liabilities and the changes in the net liability for the years ended December 31 were as follows:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Net asset retirement obligation at January 1
|
$ | 19 | $ | 20 | ||||
|
Liabilities settled
|
(12 | ) | — | |||||
|
Accretion expense
|
1 | 2 | ||||||
|
Changes in estimate
|
— | (3 | ) | |||||
|
Net asset retirement obligation at December 31(1)
|
$ | 8 | $ | 19 | ||||
____________
(1) For the year ended December 31, 2010 and 2009, approximately $1 million and $14 million of this amount are reflected in current liabilities.
6. Debt
Our long-term debt consisted of the following at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
5.90% Notes due April 2017
|
$ | 500 | $ | 500 | ||||
|
7.35% Notes due February 2031
|
153 | 153 | ||||||
|
8.0% Notes due March 2032
|
258 | 258 | ||||||
| 911 | 911 | |||||||
|
Less: Unamortized discount
|
1 | 1 | ||||||
|
Total long-term debt
|
$ | 910 | $ | 910 | ||||
Under our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens. Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $10 million cross-acceleration clause. If triggered, repayment of the long-term debt that contains these provisions could be accelerated. For the year ended December 31, 2010, we were in compliance with our debt-related covenants.
7. Commitments and Contingencies
Legal Proceedings
We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2010, we had approximately $2 million accrued for our outstanding legal matters.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2010, we had no accrual for our environmental matters, and at December 31, 2009, we accrued approximately $1 million for expected remediation costs and associated onsite, offsite and groundwater technical studies.
Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.
We expect to make capital expenditures for environmental matters of approximately $3 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Rates and Regulatory Matter
Rate Case. In January 2010, the FERC approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012, but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013.
Other Commitments
Capital Commitments. At December 31, 2010, we had capital commitments of approximately $27 million primarily related to our South System III and Southeast Supply Header Phase II projects, all of which is expected to be spent in 2011. During 2009, we entered into an approximately $57 million letter of credit associated with our estimated construction costs related to our Southeast Supply Header project. As invoices are paid under the contract, we are able to reduce the value of the letter of credit. At December 31, 2010, the letter of credit has been reduced to approximately $31 million. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
Other Commitments. We have entered into unconditional commitments primarily for storage services, totaling approximately $14 million at December 31, 2010. Our annual obligations under these purchase obligations are $11 million in 2011, $1 million in 2012, and $2 million in 2013. We also hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Currently, our obligations under these easements are not material to the results of our operations.
Operating Leases. We lease property, facilities and equipment under various operating leases. Our primary commitment under operating leases is the lease of our office space in Birmingham, Alabama. El Paso guarantees our obligations under these lease agreements. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:
|
Year Ending
December 31,
|
(In millions)
|
||||
|
2011
|
$ | 3 | |||
|
2012
|
3 | ||||
|
2013
|
3 | ||||
|
2014
|
3 | ||||
|
2015
|
3 | ||||
|
Thereafter
|
5 | ||||
|
Total
|
$ | 20 | |||
Rent expense on our lease obligations for each of the years ended December 31, 2010, 2009 and 2008 was $4 million. These amounts include our share of rent allocated to us from El Paso.
Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of performance guarantees that are not recorded in our financial statements. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. As of December 31, 2009, we had performance guarantees related to construction contracts held by Southern LNG Company, L.L.C and Elba Express our affiliates. These guarantees expired in 2010, upon completion of the construction projects.
Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after June 30, 2000 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $1 million to our postretirement benefit plan in 2011.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability as allowed by the FERC. These amounts would otherwise be recorded in accumulated other comprehensive income for non-regulated entities.
The table below provides information about our postretirement benefit plan:
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Change in accumulated postretirement benefit obligation:
|
||||||||
|
Accumulated postretirement benefit obligation - beginning of period
|
$ | 59 | $ | 61 | ||||
|
Interest cost
|
3 | 4 | ||||||
|
Participant contributions
|
1 | 1 | ||||||
|
Actuarial gain
|
(1 | ) | (1 | ) | ||||
|
Benefits paid(1)
|
(4 | ) | (6 | ) | ||||
|
Accumulated postretirement benefit obligation - end of period
|
$ | 58 | $ | 59 | ||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets - beginning period
|
$ | 52 | $ | 46 | ||||
|
Actual return on plan assets
|
5 | 8 | ||||||
|
Employer contributions
|
1 | 4 | ||||||
|
Participant contributions
|
1 | — | ||||||
|
Benefits paid
|
(4 | ) | (6 | ) | ||||
|
Fair value of plan assets - end of period
|
$ | 55 | $ | 52 | ||||
|
Reconciliation of funded status:
|
||||||||
|
Fair value of plan assets
|
$ | 55 | $ | 52 | ||||
|
Less: accumulated postretirement benefit obligation
|
58 | 59 | ||||||
|
Net liability at December 31
|
$ | (3 | ) | $ | (7 | ) | ||
____________
(1) Amounts shown net of a subsidy of less than $1 million for the years ended December 31, 2010 and 2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.
We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $3 million and common collective trust funds with a fair value of $52 million. As of December 31, 2009, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $50 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawal in certain situations such as market conditions or at the issuer’s discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.
Expected Payment of Future Benefits. As of December 31, 2010, we expect the following benefit payments under our plan:
|
Year Ending
December 31,
|
|
Expected
Payments(1)
|
|||
|
(In millions)
|
|||||
|
2011
|
$ | 4 | |||
|
2012
|
4 | ||||
|
2013
|
4 | ||||
|
2014
|
4 | ||||
|
2015
|
4 | ||||
|
2016 – 2020
|
21 | ||||
____________
(1) Includes a reduction of less than $1 million in each of the years 2011 – 2015 and approximately $4 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:
|
2010
|
2009
|
2008
|
||||||||||
|
(Percent)
|
||||||||||||
|
Assumptions related to benefit obligations at December 31:
|
||||||||||||
|
Discount rate
|
4.92 | 5.51 | 6.00 | |||||||||
|
Assumptions related to benefit costs for the year ended December 31:
|
||||||||||||
|
Discount rate
|
5.51 | 6.00 | 6.05 | |||||||||
|
Expected return on plan assets(1)
|
7.75 | 8.00 | 8.00 | |||||||||
____________
(1) The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.
39
Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4 percent, gradually decreasing to 5.0 percent by the year 2016. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2010 or 2009. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2010 and 2009:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
One percentage point increase:
|
||||||||
|
Accumulated postretirement benefit obligation
|
$ | 5 | $ | 5 | ||||
|
One percentage point decrease:
|
||||||||
|
Accumulated postretirement benefit obligation
|
$ | (4 | ) | $ | (4 | ) | ||
Components of Net Benefit Cost. For each of the years ended December 31, the components of net benefit cost are as follows:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Interest cost
|
$ | 3 | $ | 3 | $ | 4 | ||||||
|
Expected return on plan assets
|
(2 | ) | (2 | ) | (3 | ) | ||||||
|
Amortization of net actuarial gain
|
— | — | (1 | ) | ||||||||
|
Net benefit cost
|
$ | 1 | $ | 1 | $ | — | ||||||
9. Transactions with Major Customers
The following table shows revenues from our major customers for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
SCANA Corporation(1)
|
$ | 92 | $ | 83 | $ | 79 | ||||||
|
Southern Company Services
|
62 | 58 | 55 | |||||||||
____________
(1) A significant portion of revenues received from a subsidiary of SCANA Corporation resulted from firm capacity released by Atlanta Gas Light Company under terms allowed by our tariff.
10. Accounts Receivable Sales Program
During 2009, we had an agreement to sell a senior interest in certain accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained subordinated interest in those receivables. The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the years ended December 31, 2009 and 2008, we received $299 million and $280 million of cash related to the sale of the senior interest, collected $228 million and $275 million from the subordinated interest we retained in the receivables, and recognized a loss of less than $1 million in both periods on these transactions. At December 31, 2009, the third party financial institution held $30 million of senior interest and we held $19 million of subordinated interest. Our subordinated interest was reflected in accounts receivable on our balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $30 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the program, as operating cash flows on our statement of cash flows.
In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third party financial institution held $56 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $629 million of accounts receivable to the third party financial institution, for which we received approximately $395 million of cash up front and had a deferred purchase price of approximately $234 million. We received approximately $208 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $26 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program as operating cash flows on our statement of cash flows.
Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2010, 2009 and 2008.
The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.
11. Investment in Unconsolidated Affiliate and Transactions with Affiliates
Investment in Unconsolidated Affiliate
Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Tennessee Gas Pipeline Company (TGP), our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2010, 2009 and 2008, we received $14 million, $13 million and $16 million in cash distributions from Bear Creek. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. Included in this amount was a return of capital of $15 million.
Summarized financial information of our proportionate share of Bear Creek as of and for the years ended December 31 is presented as follows:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Operating results data:
|
||||||||||||
|
Operating revenues
|
$ | 19 | $ | 18 | $ | 20 | ||||||
|
Operating expenses
|
5 | 7 | 8 | |||||||||
|
Income from continuing operations and net income
|
14 | 11 | 13 | |||||||||
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Financial position data:
|
||||||||
|
Current assets
|
$ | 5 | $ | 28 | ||||
|
Non-current assets
|
52 | 52 | ||||||
|
Other current liabilities
|
2 | 1 | ||||||
|
Equity in net assets
|
55 | 79 | ||||||
Transactions with Affiliates
Distributions. We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2010, 2009 and 2008, we paid cash distributions of approximately $257 million, $171 million and $200 million to our partners. In addition, in January 2011 we paid a cash distribution to our partners of approximately $47 million.
Cash Management Programs. In conjunction with EPB’s acquisition of an additional interest in us in November 2010, we began to participate in EPB’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing our total borrowings from outside sources. EPB uses the cash management program to settle intercompany transactions between participating affiliates. At December 31, 2010, we had a note payable to EPB of approximately $12 million which was classified as current on our balance sheet. The interest rate on this variable rate note was 0.8% at December 31, 2010.
Also, in conjunction with EPB’s acquisition of the additional interest in us as described above, we terminated our participation in El Paso’s cash management program and received cash of approximately $5 million from El Paso in settlement of the final note receivable balance. At December 31, 2009, we had a $154 million note receivable from El Paso of which $42 million was classified as current on our balance sheet. The interest rate on this variable rate note was 1.5% at December 31, 2009.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to affiliates under long-term contracts.
We do not have employees and we are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from TGP, our affiliate, associated with our pipeline services. These allocations are based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, gross property and payroll.
The following table shows overall revenues, expenses and reimbursements from our affiliates for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Revenues
|
$ | 8 | $ | 6 | $ | 6 | ||||||
|
Operation and maintenance expenses
|
115 | 125 | 120 | |||||||||
|
Reimbursement of operating expenses
|
4 | 14 | 13 | |||||||||
12. Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.
|
Quarters Ended
|
||||||||||||||||||||
|
March 31
|
June 30
|
September 30
|
December 31
|
Total
|
||||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Operating revenues
|
$ | 145 | $ | 131 | $ | 134 | $ | 138 | $ | 548 | ||||||||||
|
Operating income
|
86 | 72 | 71 | 79 | 308 | |||||||||||||||
|
Net income
|
76 | 60 | 60 | 71 | 267 | |||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating revenues
|
$ | 126 | $ | 119 | $ | 124 | $ | 141 | $ | 510 | ||||||||||
|
Operating income
|
64 | 57 | 57 | 77 | 255 | |||||||||||||||
|
Net income
|
48 | 48 | 45 | 67 | 208 | |||||||||||||||
SCHEDULE II
SOUTHERN NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
(In millions)
|
Description
|
Balance at
Beginning
of Period
|
Charged to
Costs and
Expenses
|
Deductions
|
Charged to
Other
Accounts
|
Balance at
End of Period
|
|||||||||||||||
|
2010
|
||||||||||||||||||||
|
Legal reserves
|
$ | 2 | $ | — | $ | — | $ | — | $ | 2 | ||||||||||
|
Environmental reserves
|
1 | — | (1 | ) | — | — | ||||||||||||||
|
2009
|
||||||||||||||||||||
|
Legal reserves
|
$ | 2 | $ | — | $ | — | $ | — | $ | 2 | ||||||||||
|
Environmental reserves
|
1 | — | — | — | 1 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Legal reserves
|
$ | 2 | $ | — | $ | — | $ | — | $ | 2 | ||||||||||
|
Environmental reserves
|
1 | — | — | — | 1 | |||||||||||||||
None.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Security and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control over Financial Reporting.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
None.
Management Committee and Executive Officers
We are a Delaware general partnership with two partners, the first of which is a wholly owned subsidiary of EPB (the “EPB Partner”), and the second of which is a wholly owned subsidiary of El Paso (the “El Paso Partner”). The EPB Partner owns a 60 percent interest in our partnership, and the El Paso Partner owns our remaining 40 percent interest. A general partnership agreement governs our ownership and management. Although our management is vested in our partners, the partners have agreed to delegate our management to a management committee. Decisions of or actions taken by the management committee are binding on us. The management committee is composed of four representatives, with three representatives being designated by the EPB Partner and one representative being designated by the El Paso Partner. Each member of the management committee has full authority to act on behalf of the partner that designated such member with respect to matters pertaining to us. Each member of the management committee is entitled to one vote on each matter submitted for a vote of the management committee, and the vote of a majority of the members of the management committee constitutes action of the management committee, except for certain actions specified in the general partnership agreement that require unanimous approval of the management committee. Our officers are appointed by the management committee.
The following provides biographical information for each of our management committee members, including the experience, qualifications, attributes or skills of such individuals, as well as information regarding our executive officers, as of February 25, 2011.
There are no family relationships among any of our executive officers or management committee members, and, unless described herein, no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.
|
Name
|
Age
|
Position
|
||
|
Norman G. Holmes
|
54
|
President, and Management Committee Member
|
||
|
John R. Sult
|
51
|
Executive Vice President and Chief Financial Officer
|
||
|
James C. Yardley
|
59
|
Management Committee Member
|
||
|
Daniel B. Martin
|
54
|
Senior Vice President and Management Committee Member
|
||
|
Michael J. Varagona
|
55
|
Vice President, Business Development and Management Committee Member
|
Norman G. Holmes. Mr. Holmes has been President of Southern Natural Gas Company since August 2010, a member of the Management Committee since November 2007, and Senior Vice President and Chief Commercial Officer from August 2006 to August 2010. Mr. Holmes has served as President of Tennessee Gas Pipeline Company and as a member of its Board of Directors since August 2010. He previously served as a Director of Southern Natural Gas Company from November 2005 to November 2007. Mr. Holmes served as Vice President, Business Development of Southern Natural Gas Company from 1999 to 2006 and as Vice President and Controller from 1995 to 1999. Mr. Holmes also serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.
Mr. Holmes’ day to day leadership as our President provides him with an intimate knowledge of our partnership, including its strategies, operations and markets. In addition, his experience as President of Tennessee Gas Pipeline Company provides the Management Committee with important operational and management experience.
John R. Sult. Mr. Sult has been Executive Vice President and Chief Financial Officer of Southern Natural Gas Company since March 2010 and Senior Vice President and Chief Financial Officer from November 2009 to March 2010. Mr. Sult previously served as Senior Vice President, Chief Financial Officer and Controller from November 2005 to November 2009. Mr. Sult also serves as Executive Vice President and Chief Financial Officer of our parent El Paso and as Executive Vice President and Chief Financial Officer of our affiliates El Paso Natural Gas Company, Colorado Interstate Gas Company, and Tennessee Gas Pipeline Company. Mr. Sult previously served as Senior Vice President and Controller of El Paso from November 2005 to November 2009. Mr. Sult held the position of Vice President and Controller at Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. Mr. Sult also serves as Director, Executive Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.
James C. Yardley. Mr. Yardley has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and served as President from May 1998 to August 2010. Mr. Yardley previously served as Chairman of the Board of Southern Natural Gas Company from May 2005 to November 2007 and a Director from November 2001 to November 2007. He has been Executive Vice President of our parent El Paso with responsibility for the regulated pipeline business unit since August 2006. Mr. Yardley serves on the board of Interstate Natural Gas Association of America and previously served as its chairman. Mr. Yardley also serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.
As Executive Vice President of El Paso Corporation’s Pipeline Group, Mr. Yardley brings a wealth of operating experience to our Management Committee as well as an extensive understanding of the pipeline industry overall. In addition, Mr. Yardley’s experience as President and Chief Executive Officer of El Paso Pipeline Partners, L.P. further augments his knowledge and experience.
Daniel B. Martin. Mr. Martin has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Senior Vice President since June 2000. He previously served as a Director of Southern Natural Gas Company from May 2005 to November 2007. Mr. Martin has been a Director of our affiliates El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. Mr. Martin has been Senior Vice President of Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of El Paso Natural Gas Company since February 2000. He served as a Director of ANR Pipeline Company from May 2005 through February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007. Mr. Martin also serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P. Mr. Martin is currently a member of the board of directors of Citrus Corp., a joint venture between El Paso Citrus Holdings, Inc. and Cross Country Citrus, LLC.
With his years of experience with El Paso’s pipeline subsidiaries, Mr. Martin brings comprehensive knowledge and understanding of the pipeline industry. In particular, Mr. Martin provides the Management Committee with valuable leadership and experience in pipeline safety, compliance and emergency response.
Michael J. Varagona. Mr. Varagona has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and Vice President of Business Development since January 2007. Mr. Varagona served as Director, Business Development from January 2004 to December 2006.
Mr. Varagona has over 32 years experience in the natural gas industry, including significant experience in marketing and business development, transmission and liquefied natural gas infrastructure. In particular, he was a major participant in the reactivation of the Elba Island LNG Terminal in Savannah, Georgia, and has worked with numerous LNG suppliers and markets to develop more than $1.2 billion in LNG-related infrastructure.
Audit Committee, Compensation Committee and Code of Ethics
As a majority owned subsidiary of EPB, we rely on EPB for certain support services. As a result, we do not have a separate corporate audit committee or audit committee financial expert, or a separate compensation committee. Also, we have not adopted a separate code of ethics. However, our executives are subject to El Paso’s code of ethics, referred to as the “Code of Conduct”. The Code of Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Conduct. A copy of the Code of Conduct is available for your review at El Paso’s website, www.elpaso.com.
All of our executive officers are officers or employees of El Paso or one of its non-SNG subsidiaries and devote a substantial portion of their time to El Paso or such other subsidiaries. None of these executive officers receives any compensation from SNG or its subsidiaries. The compensation of our executive officers is set by El Paso, and we have no control over the compensation determination process. Our executive officers and former employees participate in employee benefit plans and arrangements sponsored by El Paso. We have not established separate employee benefit plans and we have not entered into employment agreements with any of our executive officers.
The members of our management committee are also officers or employees of El Paso or one of its non-SNG subsidiaries and do not receive additional compensation for their service as a member of our management committee.
We are a Delaware general partnership. We are owned 60 percent by EPPP SNG GP Holdings, L.L.C., a wholly-owned subsidiary of EPB, and 40 percent by EPPP SNG GP Holdings, L.L.C., a wholly-owned subsidiary of El Paso. The address of each of El Paso and EPB is 1001 Louisiana Street, Houston, Texas 77002.
The following table sets forth, as of February 17, 2011, the number of shares of common stock of El Paso owned by each of our executive officers and management committee members and all of our management committee members and executive officers as a group.
|
Name of Beneficial Owner
|
|
Shares of
Common
Stock
Owned
Directly or
Indirectly
|
Shares
Underlying
Options
Exercisable
Within
60 Days(1)
|
Total Shares
of Common
Stock
Beneficially
Owned
|
Percentage of
Total Shares
of Common
Stock
Beneficially
Owned(2)
|
||||||||
|
Norman G.Holmes
|
65,934 | 163,210 | 229,144 | * | |||||||||
|
John R. Sult
|
116,131 | 209,897 | 326,028 | * | |||||||||
|
James C. Yardley
|
306,991 | 559,203 | 866,194 | * | |||||||||
|
Daniel B. Martin
|
162,099 | 227,670 | 389,769 | * | |||||||||
|
Michael J. Varagona
|
43,316 | 77,636 | 120,952 | * | |||||||||
|
All management committee members and executive officers as a group (5 persons)
|
694,471 | 1,237,616 | 1,932,087 | * | |||||||||
___________________
| * |
Less than 1%.
|
| (1) |
The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 17, 2011. Shares subject to options cannot be voted.
|
| (2) | Based on 704,734,612 shares outstanding as of February 17, 2011. |
The following table sets forth, as of February 17, 2011, the number of common units of EPB owned by each of our executive officers and management committee members and all of our management committee members and executive officers as a group.
| Name of Beneficial Owner | Total Common Units Beneficially Owned |
Percentage of Total Common
Units Beneficially Owned(1)
|
|||||
|
Norman G. Holmes
|
— | — | |||||
|
John R. Sult
|
10,000 | * | |||||
|
James C. Yardley
|
10,000 | * | |||||
|
Daniel B. Martin
|
— | — | |||||
|
Michael J. Varagona
|
— | — | |||||
|
All management committee members and executive officers as a group (5 persons)
|
20,000 | * | |||||
___________________
| * |
Less than 1%.
|
| (1) | Based on 177,167,863 shares outstanding as of February 17, 2011. |
El Paso Pipeline Partners L.P.
We are a general partnership presently owned 60 percent indirectly through a wholly owned subsidiary of EPB and 40 percent through a wholly owned subsidiary of El Paso.
El Paso Guarantee of SNG Lease
El Paso has guaranteed our obligations with respect to our leased headquarters.
Other Agreements and Transactions
In addition, we currently have and will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.
For a description of certain additional affiliate transactions, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.
Audit Fees
The audit fees for the years ended December 31, 2010 and 2009 of $982,000 and $792,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Southern Natural Gas Company and its subsidiaries as well as the review of documents filed with the SEC and related consent.
All Other Fees
No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2010 and 2009.
Policy for Approval of Audit and Non-Audit Fees
We are a majority owned subsidiary of both El Paso and EPB and do not have a separate audit committee. El Paso’s and EPB’s Audit Committees have adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2011 Annual Meeting of Stockholders. For a description of EPB’s pre-approval policies for audit and non-audit related services, see EPB’s Annual Report on Form 10-K for the year ended December 31, 2010.
The following documents are filed as a part of this report:
1. Financial statements
|
Page
|
|
|
The following consolidated financial statements are included in Part II, Item 8 of this report:
|
|
|
Report of Independent Registered Public Accounting Firm
|
26
|
|
Consolidated Statements of Income
|
27
|
|
Consolidated Balance Sheets
|
28
|
|
Consolidated Statements of Cash Flows
|
29
|
|
Consolidated Statements of Partners’ Capital
|
30
|
|
Notes to Consolidated Financial Statements
|
31
|
2. Financial statement schedules
|
Schedule II — Valuation and Qualifying Accounts
|
43
|
All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. Exhibits
The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
|
•
|
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
|
|
•
|
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
|
|
•
|
may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
|
|
•
|
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
|
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and our consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28th day of February 2011.
|
|
SOUTHERN NATURAL GAS COMPANY
|
|
|
By:
|
/s/ Norman G. Holmes
|
|
|
Norman G. Holmes
|
||
|
President
|
||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Southern Natural Gas Company and in the capacities and on the dates indicated:
|
Signature
|
Title
|
Date
|
||
|
/s/ Norman G. Holmes
|
President and Management Committee Member
|
February 28, 2011
|
||
|
Norman G. Holmes
|
(Principal Executive Officer)
|
|||
| /s/ John R. Sult |
Executive Vice President and
|
February 28, 2011
|
||
|
John R. Sult
|
Chief Financial Officer
|
|||
|
(Principal Financial Officer)
|
||||
|
/s/ Rosa P. Jackson
|
Vice President and Controller
|
February 28, 2011
|
||
|
Rosa P. Jackson
|
(Principal Accounting Officer)
|
|||
|
/s/ Daniel B. Martin
|
Management Committee Member
|
February 28, 2011
|
||
|
Daniel B. Martin
|
|
|||
|
/s/ Michael J. Varagona
|
Management Committee Member
|
February 28, 2011
|
||
|
Michael J. Varagona
|
|
|||
|
/s/ James C. Yardley
|
Management Committee Member
|
February 28, 2011
|
||
|
James C. Yardley
|
|
SOUTHERN NATURAL GAS COMPANY
EXHIBIT INDEX
December 31, 2010
Each exhibit identified below is filed as part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
|
Exhibit Number
|
Description
|
|
|
3.A
|
Certificate of Conversion (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
|
|
|
3.B
|
Statement of Partnership Existence (incorporated by reference to Exhibit 3.B to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
|
|
|
3.C
|
General Partnership Agreement dated November 1, 2007 (incorporated by reference to Exhibit 3.C to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
|
|
|
3.D
|
First Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated September 30, 2008 (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).
|
|
|
3.E
|
Second Amendment to General Partnership Agreement of Southern Natural Gas Company, dated June 23, 2010 (incorporated by reference to Exhibit 3.A to our Quarterly Report on Form 10-Q for the period ended June 30, 2010, filed with the SEC on August 6, 2010).
|
|
|
3.F
|
Third Amendment to General Partnership Agreement of Southern Natural Gas Company, dated June 30, 2010 (incorporated by reference to Exhibit 3.B to our Quarterly Report on Form 10-Q for the period ended June 30, 2010, filed with the SEC on August 6, 2010).
|
|
|
3.G
|
Fourth Amendment to the General Partnership Agreement of Southern Natural Gas Company, dated November 19, 2010 (incorporated by reference to Exhibit 3 to our Current Report on Form 8-K filed with the SEC on November 24, 2010).
|
|
|
4.A
|
Indenture dated June 1, 1987 between Southern Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); First Supplemental Indenture, dated as of September 30, 1997, between Southern Natural Gas Company and the Trustee (incorporated by reference to Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Second Supplemental Indenture dated as of February 13, 2001, between Southern Natural Gas Company and the Trustee (incorporated by reference to Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007); Third Supplemental Indenture dated as of March 26, 2007 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on March 28, 2007); Fourth Supplemental Indenture dated as of May 4, 2007 among Southern Natural Gas Company, Wilmington Trust Company (solely with respect to certain portions thereof) and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.C to our quarterly report on Form10-Q for the period ended March 31, 2007, filed with the SEC on May 8, 2007); Fifth Supplemental Indenture dated October 15, 2007 by and among SNG, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on October 16, 2007); Sixth Supplemental Indenture dated November 1, 2007 by and among SNG, Southern Natural Issuing Corporation, Wilmington Trust Company, as trustee, and The Bank of New York Trust Company, N.A., as series trustee, to Indenture dated as of June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
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4.B
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Form of 5.90% Note due 2017 (included as Exhibit A to Exhibit 4.A of our Current Report on Form 8-K filed with the SEC on March 28, 2007).
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4.C
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Indenture dated as of March 5, 2003 between Southern Natural Gas Company and The Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.C to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010).
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*12
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Ratio of Earnings to Fixed Charges. | |
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*21
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Subsidiaries of Southern Natural Gas Company.
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*23.A
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Consent of Independent Registered Public Accounting Firm Ernst & Young, LLP.
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*31.A
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Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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*31.B
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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*32.A
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Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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*32.B
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Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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52